Substations in high and medium-voltage power networks include primary devices such as electrical cables, lines, bus bars, switches, power transformers and instrument transformers, which are generally arranged in switch yards and/or bays. These primary devices are operated in an automated way via a Substation Automation (SA) system. The SA system includes secondary devices, so-called Intelligent Electronic Devices (IED), which are responsible for protection, control and monitoring of the primary devices. The IEDs may be assigned to hierarchical levels, for example, the station level, the bay level, and the process level, the latter being separated from the bay level by a so-called process interface. The station level of the SA system includes an Operator Work Station (OWS) with a Human-Machine Interface (HMI) and a gateway to a Network Control Center (NCC).
A communication standard for communication between the secondary devices of a substation has been introduced by the International Electrotechnical Committee (IEC) as part of the standard IEC 61850 entitled “Communication Networks and Systems In Substations”. For non-time critical messages, IEC 61850-8-1 specifies the Manufacturing Message Specification (MMS, ISO/IEC 9506) protocol based on a reduced Open Systems Interconnection (OSI) protocol stack with the Transmission Control Protocol (TCP) and Internet Protocol (IP) in the transport and network layer, respectively, and Ethernet as physical media.
SA systems based on IEC 61850 are configured and described by means of a standardized configuration representation or formal system description called Substation Configuration Description (SCD). An SCD file includes the logical data flow between the IEDs on the basis of message types or data sets, for example, for every message source, a list of destination or receiver IEDs, the message size in terms of data set definitions, as well as the message sending rates for all periodic traffic. The SCD file likewise includes the relationship between the IEDs as well as the functionality which the IEDs execute on behalf of the substation process or switch yard. SA systems with IEC 61850 have different architectures and different ways of allocating functionality to Logical Devices (LD) or to physical devices (IEDs). The names of some IEDs are even dependent on the IED manufacturer and/or the IED purpose.
In order to interconnect IEC 61850 IEDs within the substation to an IEC 61850 NCC, the TCP/IP based client server part of the IEDs and the NCC can directly be used across any wide area network. However, this implies separate permanent TCP/IP connections to each individual IED inside the SA system and extensive resources and management at the NCC side, and makes the NCC configuration highly dependent on the IED architecture within the substation. Furthermore, means for switching control access between substation level and NCC level (e.g., between local and remote) must be implemented on all SA IEDs.
As an alternative, the use of a gateway from the SA side IEC 61850 bus to the NCC side IEC 61850 protocol has been recommended. Such a gateway operates as an IEC 61850 client to all those IEDs supplying process data (such as primary equipment status, e.g. switch position, or primary equipment supervision data e.g. gas alarms) intended for the NCC, and as an IEC 61850 server to the NCC for providing any process data changes in a configurable and controlled way via the MMS/TCP/IP part of IEC 61850. The gateway requires a configuration related to the SA system and its communication system on one side, and to the needed signals and signal qualities at the NCC on the other side. One simple method of configuring the server side of the gateway is to instantiate proxy Logical Devices (LD) for all the LDs on the substation IEDs to the NCC side of the gateway. This leads to a simple gateway configuration and also testing process; however, it makes the NCC communication link dependent on the IED related naming and the physical as well as logical device structure within the substation.
On the other hand, for the NCC, a substation related functional view based on the primary substation single line layout and corresponding equipment and functions may be beneficial. Such functional structure changes much less than the physical structure inside the secondary SA system, and might even to a large extent be known before the design of the SA system is finalized. Likewise, later extensions of the primary part of the substation and the corresponding functionality might be known long before the specific IEDs for the implementation have been determined.
In this context, the principles and methods of the present disclosure are by no means restricted to a use in substation automation, but are likewise applicable to related process control systems with a formal system description. In particular, it has to be noted that IEC 61850 is also an accepted standard for Hydro power plants, Wind power systems, and Distributed Energy Resources (DER). Further, it is also applicable to other protocols, as long as there is a formal description of the signal meaning, like for IEC 60870-5-101/104 according to IEC 61850-80-1.